Petrochemical Processes
In petrochemical processes, ethylene is the lightest olefinic hydrocarbon and represents the largest building block for a variety of petrochemical products such as plastics, resins, fibers, solvents, etc. Ethylene does not occur freely in nature and is produced primarily from the thermal cracking of hydrocarbon feedstocks derived from natural gas and crude oil. The conventional hydrocarbon feedstocks used for the production of ethylene include ethane, propane, butane, pentanes and naphthas. Naphtha cracking represents about 45% of world production capacity, whereas nearly 35% of capacity is produced from ethane cracking. Other possible feeds include refinery offgas, natural gasoline liquids, wide-boiling condensate fractions, atmospheric and vacuum gas oils, and hydrotreated or hydrocracked vacuum gas oils.
The thermal cracking of hydrocarbon feedstocks, which is the main route to ethylene production, is carried out in tubular coils located in the radiant zone of fired heaters. Steam is added to reduce the partial pressure of the hydrocarbons in the radiant coils. The reactions that result in the transformation of mostly saturated hydrocarbons to olefins are highly endothermic and require reactor temperature in the range of 750 to 1050° C. depending on the feedstock and design of the reactor coils. Thermal cracking reactions also produce valuable by-products, including propylene, butadiene, benzene, gasoline, and hydrogen. The on-stream availability of the thermal cracking reactor is it determined by coking of either the cracking coils or the cracked effluent transfer line exchangers (TLEs). Coke is produced from aromatic feed component as a side product of thermal cracking and deposits on the radiant coil walls and inside the tubes of TLEs. This limits the heat transfer and increases the pressure drop, thus reducing the olefin selectivity. The run length is normally determined by the tube metal temperature increase of the radiant coil, the outlet temperature of the TLE, or the increased pressure drop.
Coke is believed to be formed by two mechanisms—catalytic and polymerization. The metal surface of the cracker coil catalyzes the growth of a filamentary type of coke and contains metal particles. The second type of coke is formed by condensation, polymerization, and/or agglomeration of heavies in the gaseous phase. The coking behavior of various feedstocks differs in cracking coils and TLEs, and these can be influenced by contaminants in the feed, dilution steam, and coil surface. In addition to general coking in cracking coils and TLEs, ethane and propane cracking plants experience coking at the inlet (on the tubesheet) of the TLEs due to gas-phase reactions at higher inlet temperatures and to the discontinuities in flow distribution. This inlet coking normally results in high-pressure drop, limiting the run length. Liquid-feed cracking results in coking on the TLE tubes near the outlet. This is caused by the condensation of tarry materials, which form a thin, oily layer that gradually polymerizes.
Steam cracking heaters are a very important part of an ethylene plant. Thermal cracking of hydrocarbons takes place in tubular coils placed in the center of a fired radiant box. The cracked effluents leave the radiant coils at a temperature of 750 to 1050° C., depending on feedstock, cracking severity, and selectivity. In order to maintain the overall process efficiency, it is required to efficiently recover the heat in the cracked effluents. The cracked effluents also need to be quenched quickly to stop secondary reactions that result in yield degradation. This is achieved by the TLEs, which cool the furnace effluents to nearly 350 to 450° C. at clean conditions, and this heat is used to generate very high pressure steam (˜125 bar). The higher steam pressure results in higher tube metal temperature and therefore minimizes condensation of tarry materials.
The typical steam cracking heater consists of a convection section in the upper offset arrangement and a radiant section at the lower end. The vertical radiant coils are located close to the center plane of the radiant box and are suspended on a hanging system from the top of the radiant box. The hanging system allows the radiant coils to expand without causing any additional stresses on the radiant coils. The radiant coils are centrifugally cast from 25Cr/35Ni or 35Cr/45Ni alloys for their carburization and creep resistance. These materials have a maximum service temperature of up to 1150° C. The typical composition of radiant coil materials is shown in Table 1. The convection section recovers the flue-gas heat by preheating the hydrocarbon feedstocks and dilution steam. In addition, heat is recovered through boiler feed water preheating and superheating of very high pressure steam. The high temperature coil or part thereof is bare due to excessive tube metal temperatures, and normally all the other convection coils have fins to improve the heat-transfer coefficient.
TABLE 1Typical composition of radiant coil materialName of MaterialsElements in weight % (Balance is Fe)HP45Nb23~27Cr, 33~38Ni, 1.2~1.8Si, 1.2~1.7Mn, 0.2 max. Mo, 0.4~0.5C,0.6~1.6Nb, 0.020 max. P, 0.020 max. SHP16Nb22.5~26Cr, 35.5~37Ni, 1.2~1.8Si, 1.2~1.6Mn, 0.2 max. Mo, 0.14~0.18C,0.7~1.4Nb, 0.020 max. P, 0.020 max. SHN10NiNb18~23Cr, 31~34Ni, 0.8~1.3Si, 1.2~1.6Mn, 0.2 max. Mo, 0.09~0.12C,0.8~1.2Nb, 0.020 max. P, 0.020 max. SHP 40 Mod23.5~26.5Cr, 34~37Ni, 1.5~2.0Si, 1.25 max. Mo, 0.37~0.45C, otherelements (W, Nb)Pompey HP 40W24~27Cr, 33-37Ni, 1.5~2.0Si, 1.5 max. Mo, 0.37~0.50C, 3.8~5.0WPompey Manaurite23~28Cr, 33~38Ni, 1.0~2.0Si, 1.0~1.5Mo, 0.37~0.50C, other additionsXM(Nb, Ti, Zr)Manaurite XTM34~37Cr, 43~48Ni, 1.0~2.0Si, 1.0~2.0Mo, 0.4~0.45C, other additions(Nb, Ti)Kubota KHR 45A30~35Cr, 40~46Ni, 2.0 max. Si, 2.0 max. Mn, 0.4~0.6C, other additions(Nb, Ti)
All the listed materials for radiant coils and other tubular products for convection coils, TLEs, closed vent and drain systems and recycling and recovery of vent and purge streams are chromium-containing high grade alloys. The steam cracker alloy comprises at least 18 wt. % Cr and 10 wt. % Ni, and preferably at least 20 wt. % Cr and 30 wt. % Ni based on the total weight of the alloy. Corrosion protection of these materials relies on protective Cr2O3 films on the tube surface. Unfortunately, these chromia-forming materials often form a complex corrosion scale comprised of spinel and chromium carbide, leading to it rough surfaces, high surface areas, and a large number of surface sites for the anchoring of coke and coke precursors.
Currently, there are various metal-oxide-forming corrosion and coke mitigating technologies on the open market. These include SK Energy's PY-COAT™ Film, Alonizing™ coating, Westaims Coat Alloy™, and C2 Nano's MIST Inhibitor. These technologies are based on metal-oxides including alumina, silica, zirconia and combination of thereof and have demonstrated their ability to reduce the formation of coke either in the laboratory or in the field. It is claimed that the active component of each product protects against corrosion and formation of a rough corrosion scale. However, in the field, these technologies generally perform well until the second cycle, where the coating layers have been physically and/or chemically compromised. The primary cause of poor long-term performance is known to be delamination and interdiffusion of the coated material on the steam cracker tubes.
Therefore, there is a need to significantly reduce corrosion and coking in the fired heater tubes in petrochemical processing operations that does not encounter the drawbacks associated with the current technologies.
Refinery Processes
In typical refinery processes, stored heavy crude oil is cleaned of contaminants (e.g., sand, salts and water) as the first step in the refining process by passage through desalting units. The clean crude feedstock is then heated by passing the desalted crude through a series of heat exchangers. The crude is then passed through a furnace that heats the crude oil to a higher temperature. The furnace, which may be an oil, natural or refinery fuel gas-fired furnace or electrically fired furnaces, heats the oil and is injected into an atmospheric distillation tower. The extreme heat produces physical splitting of the crude oil into combustion gas (furnace fuel gas) and other gaseous light ends, liquid products, and an atmospheric resid fraction.
A large amount of heavy resid content is characteristic of heavy oils. The atmospheric resid must be subjected to more refining. Following the atmospheric tower, the resid is further heated in another series of heat exchangers and then another furnace and sent to a vacuum distillation tower, where light vacuum gas oil and heavy vacuum gas oil are extracted from the resid. The remaining tarry fluid left near the base of the vacuum tower, the vacuum residue, can either be claimed as asphalt, or (ii) subject to further processing, such as coking. In various coking processes, the resid is heated to high temperatures of 850-950° F. (454-510° C.) such that the light boiling products are thermally cracked off of the aromatic cores in the resid and are distilled overhead and the solid coke remains.
The delayed coking process is one of the most widely commercially practiced of the coking processes. The resid is heated to the coking temperature by flowing through a long tube in a furnace and then allowed to react at this elevated temperature after flowing into the bottom of a high cylindrical insulated drum. The volatile products are removed to a fractionator and coke accumulates in the drum. The heavy liquid product from the fractionator is recycled back to the furnace. When the drum fills up with coke, the feed is switched to a second drum. The coke is mined out of the drum by drilling a hole down the center with high pressure water and cutting out the remainder also with high-pressure water to get the drum ready for the next coke accumulation cycle.
In Fluid Coking™, the resid is sprayed onto a hot, fluidized bed of coke particles in a vessel (i.e., the reactor). The volatile products are removed to a fractionator while the coke particles are removed from the bottom of the vessel and transferred to another vessel (i.e., the burner), where the coke is partially burned with air to provide heat for the process. The coke then is recirculated back to the reactor. Since this process produces much more coke than is required for heating the process, fluid coke is withdrawn at the bottom of the reactor.
In FLEXICOKING™, a third vessel (i.e., the gasifier), is added to the Fluid Coking process. In the gasifier, coke is gasified with steam and air in net reducing conditions to produce a low BTU gas containing hydrogen, carbon monoxide, nitrogen, and hydrogen sulfide. The hydrogen sulfide is removed using adsorption. The remaining low BTU gas is burned as a clean fuel within the refinery and/or in a nearby power plant.
Visbreaking is a low conversion thermal process used originally to reduce the resid viscosity for heavy fuel oil applications. Today, it often uses a resid that exceeds minimum heavy fuel oil specifications and converts just it enough to obtain 15-30% transportation boiling range liquids and still have the heavy product meet heavy fuel oil specifications. Since this process cannot tolerate coke formation, it is required to be within the coke induction period that may limit conversion, rather than heavy fuel oil specifications. A visbreaker reactor may be similar to a delayed coker with a furnace tube followed by a soaker drum. However, the drum is much smaller in volume to limit the residence time with the entire liquid product flowing through. Alternatively, the entire visbreaker may be a long tube coiled within a furnace. Upsets cause coke to form and accumulate on visbreaker walls, which requires periodic decoking.
The coker tube furnace is the heart of the delayed coking process. The heater furnishes all of the heat in the process. Typically, there are two to four passes per furnace. The tubes are mounted horizontally on the side and held in place with alloy hangers. Multiple burners are along the bottom of the radiant wall opposite from the tubes and are fired vertically upward. Tall furnaces are advantageous since the roof tubes are less likely to have flame impingement and overheating by both radiation and convection. Normally just the radiant section of the heater is used to heat the oil for a delayed coker. The upper convection section of the coker heater is used in some refineries to preheat the oil going to the fractionator or for other uses (e.g., steam generation).
The radiant section tubes in a fired heater used in many refinery process units can experience fouling on the inside and/or outside of the tube surface. External tube fouling occurs when the heater is oil fired. During oil combustion solid particulate matter is formed containing carbon, sulfur and metals which are present in fuel oil. This particulate matter will over time collect on external tube surfaces. Fired heaters that heat crude and reduced crude usually experience the highest level of internal fouling. With these fluids, the fouling occurs due to (i) the presence of solids in the fluid, (ii) thermal cracking forming high molecular weight compounds and (iii) in situ corrosion products. All these materials can end up sticking to the tube wall and forming “coke”. Liquids lighter than crude can also form internal deposits. For example, fired heaters heating liquid naphtha can experience internal tube fouling due to corrosion products and/or polymerization reactions forming long chain molecules which stick to the tube wall. Internal tube fouling usually has a large impact on heater operation and thermal efficiency.
These formations/foulant/coke deposits can result in an increase in the radiant tube metal temperature (TMT). As coke forms inside the heater tube, an insulation barrier between the metal and the “colder” process fluid is formed, resulting in an increased TMT. If coking is allowed to occur without intervention, a tube rupture as a result of high TMT (due to lessened metal strength) is possible. To avoid this, heaters with internal coke deposits can be operated at reduced rates (and hence reduced efficiency and productivity) such that metallurgical constrains are not exceeded on the tubes and tube rupture is avoided. Heaters in fouling service are designed to accommodate a specified TMT increase above the clean tube condition. When that limit is reached steps must be taken to remove the foulant. Often this means the heater must be shut down for cleaning. A secondary effect of internal fouling is increased pressure drop, which limits capacity and throughput. Heaters in fouling service are also designed to accommodate a specified increase in pressure drop in most cases, the TMT limit is reached before the pressure drop limit. When coke forms in the heater tubes, it insulates the inside of the tube which results in elevated temperatures on the outside of the tube. With good operational practices, coker furnace can be operational for 18 months before decoking of the tubes is needed. Depending on the tube metallurgy, when temperatures approach 1250° F. (677° C.) on the exterior skin thermocouple, the furnace must be steam spalled and/or steam-air decoked or cooled down and cleaned by hydraulic or mechanical pigging.
During normal use, the internal surfaces of the fired heater tubes are subject to carburization sulfidation, naphthenic acid corrosion and other forms of high temperature corrosion as a result of the prolonged exposure to the stream of heavy crude oil, resid and other petroleum fractions. Carburization is a form of high temperature degradation, which occurs when carbon from the environment diffuses into the metal, usually forming carbides in the matrix and along grain boundaries at temperatures generally in excess of 1000° F. (538° C.). Carburized material suffers an increase in hardness and often a substantial reduction in toughness, becoming embrittled to the point of exhibiting internal creep damage due to the increased volume of the carbides. Crude oils and hydrocarbon fractions which contain reactive sulfur are corrosive to carbon and low/medium alloy steels at temperatures above 500° F. (260° C.) and will cause sulfidation corrosion which forms iron sulfide. This sulfide scale that is formed is often referred to as sulfide induced fouling. Those which contain naphthenic acidic components are corrosive to carbon and low/medium alloy steels at temperatures above 400° F. (204° C.) and directly remove metal from the surface of the fired heater tube. Corrosion on the internal surfaces of the fired heater tubes creates an uneven surface that can enhance fouling because the various particles found in the petroleum stream may attach themselves to the roughened surface it is also suggested that corroded surfaces may also provide a “more hospitable” surface for foulant lay down.
Synthetic crudes are derived from processing of bitumens, shale, tar sands or extra heavy oils and are also processed in refinery operations. These synthetic crudes present additional fouling problems, as these feedstocks are too heavy and contaminant laden for the typical refinery to process. The materials are often pre-treated at the production site and then shipped to refineries as synthetic crudes. These crudes may contain fine particulate siliceous inorganic matter, such as in the case of tar sands. Some may also contain reactive olefinic materials that are prone to forming polymeric foulant deposits within the fired heater tubes.
Currently, there are various surface modification techniques available for reducing corrosion and fouling in the fired heater tubes for refinery operations. Most of them are based on thin film coatings and include alonizing, hexamethyldisilazane (HMDS) and liquid phase silicate coatings. Alonizing is a diffusion alloying method and applied to the metal surface at elevated temperatures. As a result, about 100μ thick, aluminum enriched layer forms on the metal surface. However, this coating, as characteristic of all such relatively thin coatings, reveals poor mechanical integrity and thermal stability due to presence of voids, defects and intermetallic brittle phases in the layer and has low reliability.
Therefore, there is a need to significantly reduce corrosion and fouling in the fired heater tubes in refinery processing operations that does not encounter the drawbacks associated with the current techniques.